1. Field of the Invention
The invention relates generally to oil and gas exploration, particularly to methods and systems for estimating fracture apertures in the formations and for assessing fracture aperture changes in response to well stress.
2. Background Art
Fractures in the formation may be storage sites for hydrocarbons or they may enhance permeability of formations by connecting pores that might contain hydrocarbons. Therefore, identification and characterization of fractures is an important part of formation characterization. Fractures are cracks or surface breakages within rocks. When there is relative movement (displacement) of the rocks across the fracture face, the fracture may be referred to as a fault or joint, depending on the relative movement. For convenience, “fracture” will be used in a general sense in this description to include fractures, faults, joints, or other similar geological features.
Locating the intervals where the borehole intercepts large and/or numerous fractures (e.g., fracture swarms) is important to characterize the fractured reservoir and to optimize completion and production operations.
Determining natural fracture aperture is also essential to estimate permeability in Fractured Reservoir Formation. In the case where fracture is the primary, or an important contributor, to the reservoir storage, natural fracture aperture is also essential to determine the formation porosity.
Various methods have been proposed to detect fractures and estimate their aperture from resistivity log (Sibbit and Faivre, 1985, “The Dual Laterolog Response in Fractured Rock,” Transaction of SPWLA 26-th Annual Logging Symposium, 1985, Dallas, paper T), borehole image (Luthi and Souhaite, 1990, “Fracture aperture from electrical borehole scans,” Geophysics, 1990, vol 55; Cheung and Heliot, 1990 “Workstation-based Fracture Evaluation Using Borehole Images and Wireline Logs,” SPE 20573), and sonic measurement (Hornby and Johnson, 1986, Winkler K, Plumb R., “Fracture Evaluation using reflected Stoneley Wave arrivals,” Geophysics, 1986, vol 54.).
Seismic data is commonly used for acquiring information about subsurface structures. Changes in the elastic properties of subsurface rocks appear as seismic reflections. Such changes in the properties of the rocks typically occur at boundaries between geologic formations, at fractures and at faults. For example, U.S. Pat. No. 3,668,619 describes the rotation of a logging tool having a single acoustic transducer that senses the reflected acoustic energy to detect fractures. U.S. Pat. No. 5,121,363 describes a method for locating a subsurface fracture based on an orbital vibrator equipped with two orthogonal motion sensors and an orientation detector.
Sonic measurements are sensitive to natural fractures (Hornby B. et al, 1986), but also to stresses and local borehole damage, making it difficult to use them systematically to quantify fracture characteristics.
In addition to seismic or sonic measurements, other measurements have also been used to locate fractures. For example, U.S. Pat. No. 4,802,144 uses the measurement of hydraulic impedance to determine fractures. U.S. Pat. No. 2,244,484 measures downhole impedance to locate fractures by determining propagation velocity. Resistivity tools are particularly useful in this regard. Similarly, U.S. Pat. No. 6,798,208, issued to Omeragic, which discloses a method for detecting a fracture in an earth formation using a propagation tool. The method includes the steps of producing electromagnetic fields using a transverse magnetic dipole (TMD) transmitter in the tool; measuring corresponding voltage signals detected with one or more TMD receivers in the tool; determining harmonics from the measured signal responses by shifting the responses (e.g. by 90 degrees) and performing an addition or subtraction using the shifted response.
Separation between shallow and deep laterolog readings has also been used as an indicator of natural fractures (Sibbit and Faivre, 1985). It is often used to help distinguish natural and induced fractures after those fractures have been picked on borehole image (Cheung and Heliot, 1990). However, this type of measurement does not provide any quantitative assessment of the fracture extent and aperture.
Borehole images allow one to identify, pick and characterize individual fractures as seen on the borehole wall. Techniques exist to quantify the aperture of each fracture based on the images (Luthi and Souhaite, 1990; Cheung and Heliot, 1990). However, those measurements have a very shallow depth of investigation, making it difficult to differentiate the natural fracture characteristics from the borehole damages.
The sensitivity of multi-component induction measurement to a fracture has been demonstrated by numerical modeling and field examples. (Wang et al. 2005) Discussion centers on the sensitivity of coplanar-coil (XX and YY) and co-axial-coil (ZZ) measurement to fractures. The numerical modeling is for one individual fracture, with application primarily to hydraulic fracture.
Because fractures often contain hydrocarbons, identification and quantification of the fractures in formations penetrated by a well can provide valuable information for optimal production of the wells. Therefore, it is desirable to have methods that can detect and quantify the presence of fractures.